Crude oil contains many different chemical components. In general terms, it consists primarily of hydrocarbon compounds, with varying amounts of impurities such as metals, chlorine, sulphur, nitrogen, asphaltenes and coke. Heavy crude oil has a lower hydrogen-to-carbon ratio than lighter crude oil, so the density (or specific gravity) of heavy crude oil is greater than that of a lighter crude oil. High specific gravity and viscosity are properties of heavy oil that cause major production and handling problems.
Heavy oil is generally any crude oil with an API gravity ranging from about 11° to 20° at standard conditions and with a gas-free viscosity ranging from about 100 to 10,000 centipoises (cp) at original reservoir temperature. Ultra heavy oil, such as tar sand oil, also known as bitumen, is any crude oil with an API gravity less than about 11° and a gas-free viscosity greater than 10,000 cp. Pipeline-able oil such as synthetic crude oil typically requires an API gravity of 19° and a viscosity at room temperature below 350 cp.
A significant problem with heavy oil is the difficulty and expense entailed in increasing the volume of lighter hydrocarbons derived from a heavy oil feedstock. Typically, this is done by increasing the hydrogen-to-carbon ratio. This can be accomplished by either removing carbon or by adding hydrogen. Carbon is typically removed by coking, solvent de-asphalting, or catalytic cracking. Hydrogen is typically added by hydro-treating or hydrocracking.
Hydrocracking processes are known which utilize a catalyst in a hydrogen environment to convert heavy distillates into lighter distillates. Catalytic cracking processes further convert crude oils including synthetic crude oils to products such as gasoline or jet fuels. Such processes typically include adding to heavy oil feedstock or distillate a source of donor hydrogen such as hydrogen gas. Unfortunately, typical heavy oil feedstocks have relatively high metal content (100 parts per million or higher) and/or other impurities, including acids, chlorides and carbon residues (e.g. micro-carbon residues). The metals and other impurities limit the application of hydrocracking and hydro-treating in one or more ways: (a) the metals contaminate the catalyst; (b) the acids and chlorides corrode the hydrotreaters or catalytic crackers; and (c) the carbon residues foul either the catalysts or the equipment with carbon (coke).
Typical prior art heavy crude oil upgrading via sequential cracking and distillation is carried out in one of two ways: (1) pressurized or un-pressurized heavy crude oil cracking, without a non-condensable sweep gas, at elevated temperature with sequential venting and distillation of cracked heavy crude oil to separate cracked and un-cracked volatiles from cracked and un-cracked non-volatiles; and (2) pressurized or un-pressurized heavy crude oil cracking, with a non-condensable sweep gas, at elevated temperature with sequential venting and distillation of cracked heavy crude oil to separate cracked and un-cracked volatiles from cracked and un-cracked non-volatiles.
Pressurized or un-pressurized cracking at elevated temperature followed by sequential venting and distillation results in a) the undesirable formation of coke, at higher cracking temperatures and/or pressures, as widely seen in the prior art, or b) excessively long cracking times under conditions which minimize coke formation i.e. lower cracking temperatures.
There is substantial cracking prior art which describes undesirable coke formation in the absence of a sweep gas:
U.S. Pat. No. 4,428,824 (Choi et al.) describes cracking issues associated with feedstocks containing asphaltenes. It states, “Heretofore, visbreaking has only had a limited efficiency when processing charge stocks containing asphaltenes. In conventional visbreaking of such charge stocks a sediment in the form of coke is formed, which has the tendency to plug the visbreaker reactor, shorten production runs and result in unacceptably lengthy periods of down time”, (col. 1, lines 35 to 41). U.S. Pat. No. 5,795,464 (Sankey et al.) describes the use of visbreaking, a thermal conversion process, widely practiced commercially as a means for obtaining low levels of conversion of heavy oils, including bitumen (col. 1, lines 47 to 50). It states that “the severity of visbreaking has generally been limited by coke formation which fouls the process equipment” and that typical maximum conversion levels for visbreaking bitumen is no more than about 30 to 35% of the 525° C.+ material i.e. heavy crude oil components having boiling points above 525° C. which still leaves the bitumen too viscous for pipelining without the use of expensive diluents to drop the viscosity to an acceptable range. The patent shows in Table 1 that an Athabasca bitumen under conventional visbreaking does not meet pipeline specifications for either API specific gravity or viscosity. Furthermore, content of nickel and vanadium, both of which are undesirable in oil refinery hydrotreating and catalytic cracker operations, were high at 300 ppm (i.e. unchanged from the original bitumen feed).
WO 2005/113726 (Varadaraj et al.) discloses that heating of bitumen to 399° C., equivalent to a short visbreaking run, resulted in fouling of the visbreaker with a carbonaceous deposit in the absence of a coking inhibitor. It states, [0019] 120 g of bitumen was rapidly heated under nitrogen[350 PSI (2413.17 kPa)] to 750° F. (398.89° C.) with continuous stirring at 1500 RPM. The bitumen was allowed to react under these conditions for a period of time calculated to be equivalent to a short visbreaking run at a temperature of 875° F. (468° C.) (typically 120 to 180 “equivalent seconds”). After achieving the desired visbreaking severity, the autoclave was rapidly cooled in order to stop any further thermal conversion. The inside of the autoclave was observed to be fouled with a carbonaceous deposit when the bitumen was thermally treated as described above.”
The Varadaraj reference confirms that the “primary limitations in thermal treatment of heavy oils, such as visbreaking, are the formation of toluene insolubles (TI) at high process severities” (para. 0003, page 1). Asphaltenes and microcarbon content are virtually unchanged due to the non-visbreaking thermal treatment conditions. The process therefore would have no commercial viability in regions where long distance pipelining of heavy crude oil is the norm, such as Alberta, Canada.
The prior art describes attempts to minimize coke formation, pressurized or un-pressurized heavy crude oil cracking at elevated temperature with sequential venting, and distillation of cracked heavy crude oil to separate cracked and un-cracked volatiles from cracked and un-cracked non-volatiles in which extremely long cracking times are used.
Canadian patent application CA 2,764,676 (Corscadden et al.) describes sequential “mild controlled cracking” of heavy crude oil (page 15, lines 24-25) in which “After the mild cracking process, a light top fraction 32 (distillate containing condensable and non-condensable volatiles) can be routed from the reactor 30 to a gas liquid condensing separator process 40” (page 15, lines 25-26). Residence time is excessive at 40-180 minutes due to low cracking temperatures of 675-775° F. (357-412° C.) and pressures ≤5.50 psig. Excessive residence times result in excessive reactor sizes and equipment capital costs.
There is substantial cracking prior art which describes the use of sweep gas in combination with cracking:
CA 2,764,676 (Corscadden et al.) describes the use of 20-80 standard cubic feet (scf) of sweep gas per barrel of heavy crude oil during cracking at cracking temperatures of (675-775° F.) (357-413° C.) (page 18, lines 14 to 16). For a 10,000 barrel/day cracker the volume of gas at room temperature and atmospheric pressure in liters for a 40-minute minimum cracker residence time is given by: 10000/24*40/60*20*28.3168=157,315 liters minimum up to 629,262 liters maximum. Liters of HCO processed in a 40-minute residence time is given by: 10000/24*40/60*159=44,166 liters. This is a massive amount of gas that must be heated from room temperature to cracker temperature to prevent cracker cooling by sweep gas. So, heating this amount of sweep gas from room temperature to cracker temperature while maintaining cracker pressure increases the volume of sweep gas in the reactor by the ratio of temperatures in ° K (i.e. 686/293 or 2.34 for 413/20 ratio in ° C.) or 368,321 to 1,473,289 liters of sweep gas/cracker residence time of 40 minutes and heavy crude oil volume of 44,166 liters. This is a large amount of sweep gas, relative to the minimum cracker volume at minimum cracker residence time, especially if the gas is natural gas or hydrogen i.e. 368,321/44,166=8.34 to 1,473,289/44,166=33.4 (see page 18, line 17). Furthermore, this large volume of hot non-condensable sweep gas must be subsequently cooled so that intermixed condensable cracked heavy crude oil distillate can be condensed. This has a substantial negative impact on the operating cost of the condenser/distillation apparatus.
U.S. Pat. No. 6,086,751 (Bienstock et al.) describes a process for upgrading heavy crude oil (Venezuelan heavy crudes and bitumen) via reduction of total acid number (TAN) and viscosity. However, it states that, “The thermal treatment of this invention is not to be confused with visbreaking which is essentially a treatment of heavy oils or whole crudes at temperatures in excess of the temperatures of the thermal treatment disclosed herein” and that “The thermal treatment process of this invention is designed to minimize cracking of hydrocarbons” (col. 1, lines 41-44; and col. 3, lines 37 to 38). It requires the use of inert gas to reduce the partial pressure of water in a heavy crude oil upgrader reaction zone to maximize TAN reduction. The reaction zone must be purged with inert gas (e.g. methane) to control partial pressure, and the purge rate will generally fall in the range of 50-500 standard cubic feet per barrel (see col. 3, lines 27 to 34). It shows the use of argon as purge gas in Example 1 at 380 standard cubic feet per barrel of bitumen (col. 5, lines 48 to 49). The invention of Bienstock et al. suffers from the following disadvantages: (1) API gravity is not increased, (i.e. this technique would not produce pipeline-able heavy crude oil) and therefore requires the addition of large amounts of expensive high API condensate or sweet synthetic crude oil. (2) The metals content is not improved and remains high at 400+ ppm nickel and vanadium. (3) Purge gas requirements are very high and costly (argon purge gas is very expensive).
The prior art describes the use of tetrahydrofurfuryl alcohol (THFA) in upgrading heavy crude oil. U.S. Pat. No. 4,877,513 (Haire et al.) discloses the addition of small amounts of THFA or other alcohols to heavy oil (i.e. 1-3 weight % THFA) followed by heating at elevated temperature (e.g. up to 399° C.) in the presence of iron-containing surfaces or particles for periods of between 600 to 6000 seconds, to reduce the viscosity and specific gravity of the heavy oil. The patent states: “The process of the present invention increases the volume of light hydrocarbons distilled from a heavy oil feedstock at a selected temperature. The process of the present invention operates at low pressures (near atmospheric pressure), without an external hydrogen gas supply, and without being dependent upon a solvent extraction process. Moreover, the present invention utilizes an active reagent which is less than 3% by weight of the heavy oil feedstock.” (column 3, lines 14 to 23). Although the process of U.S. Pat. No. 4,877,513 results in a reduction of specific gravity and viscosity, it suffers from certain drawbacks which render it commercially nonviable:                the lack of a solvent extraction process to eliminate or reduce asphaltene sludge and coke, resulting in a high undesirable asphaltene or coke content and a product that is highly likely to cause unacceptable fouling of pipelines even though it may have acceptable viscosity;        low yield of sequentially distillable hydrocarbons with a boiling point at or below 525° C. (i.e. high yield of distillation residue);        the reactor is highly susceptible to “spray flow regime issues” (i.e. extreme gas formation during heavy crude oil cracking, such as the gas volumes of 59 to 213 liters for only 257 grams of heavy crude oil feed in tests 1 and 6 in Table 1);        no technique is described for recycling the alcohol additive in whole or in part;        without subsequent (sequential) distillation, the product is highly contaminated with heavy metals, and actually concentrates contained heavy metals, making it extremely difficult to hydro-treat to further reduce viscosity and/or sulphur content;        the process requires a tubular reactor, the inner walls of which must include ferrous metal with excessive reaction times e.g. 83 min for THFA in Table 1;        liquid product yields are very low ahead of distillation (e.g. 63.0% by weight, or 160 grams output per 254 grams input in Test 4, Table 1, indicating that 37% by weight of the heavy crude oil feedstock is converted to gases, asphaltene sludge or coke);        conversion level for 525° C.+ material (i.e. heavy crude oil components having boiling points above 525° C.) is extremely low at only 16% (see Table 4);        the tubular reactor (plug flow) or its iron powder or rod inserts is highly susceptible to iron corrosion for steel and iron/nickel corrosion for stainless steel at its inlet, where heavy crude oil total acidity (TAN) is at a maximum and hydrogen sulphide content of the gas phase (i.e. corrosion inhibitor) is at a minimum; for example, see: Laredo et al. “Naphthenic Acids, Total Acid Number and Sulfur Content Profile in Isthmus and Maya Crude Oils”, Fuel 83 (2004) pages 1689-1695; O. Yépez, “On the Chemical Reactions between Carboxylic Acids and Iron, Including the Special Case of Naphthenic Acids”, Fuel 86 (2007) pages 1162-1168; and O. Yépez, “Influence of Different Sulfur Compounds on Corrosion due to Naphthenic Acid”, Fuel 84 (2005), pages 97-104).        
The tubular reactor (plug flow) or its iron powder or rod inserts is highly susceptible to coking. This is confirmed by S. Raseev, in “Thermal and Catalytic Processes in Petroleum Refining”, Marcel Dekker (2003) at pages 70-71, which states: “Detailed studies using electron microscopy and X-Ray dispersion revealed that formation of coke in the furnace tubes is a stage-wise process. In the first stage, coke filaments are formed due to reactions on the metal surface catalyzed by iron and nickel. Once the coke filaments have appeared, coke formation is amplified in subsequent stages. The reduction of the catalytic effect of iron and nickel is accomplished in two ways. The second method used in industry consists of introducing into the feed, after decoking, hydrogen sulphide.”
Haire et al., U.S. Pat. No. 4,877,513, actually recommends the use of excess iron and does not suggest a need to prevent iron corrosion (i.e. formation of corroded “ionic iron”). It states: “The metallic exposure can occur by a variety of methods including without limitation heating the mixture in a metallic reactor vessel having inner walls containing ferrous metal, or adding ferrous metal particles to the mixture, or placing ferrous or steel rods in the reactor vessel, for example. It should be appreciated that use of ferrous metal particles may affect subsequent refining steps. “(col. 4, lines 56-63).” It further states: “The inventors have postulated a probable mechanism for the present invention involving an ionic iron complex. The restructuring of the hydrocarbons apparently involves a surface reaction among the reagent(s), the ferrous metal and the heavier hydrocarbons (so-called polysegmented hydrocarbons).” (col. 12, lines 58-63).
The prior art ignores the negative impact of pressure with respect to over-cracking potentially resulting in undesirable coke formation even at pressures deemed acceptable (e.g. 50 psig as in CA 2,764,676, page 18, line 9). Increasing cracker pressure from atmospheric pressure (i.e. 14.7 psig or 760 mm mercury) to, for example, 50 psig (2550 mm mercury) increases the boiling point of cracker condensable volatiles by approximately 69 to 75° C. for typical cracker components including non-cyclic alkanes, cyclic alkanes (naphthenes), aromatics and mercaptans (thiols). This can be shown by use of the Antoine equation (e.g. http://en.wikipedia.org/wiki/Antoine_equation and Wilhoit et al, 1971. “Handbook of Vapor Pressures and Heats of Vaporization of Hydrocarbons and Related Compounds”. Publication 101, The American Petroleum Institute). The following Table 1 shows the effect of pressure on the boiling point of typical cracked and un-cracked heavy crude oil components as calculated from the above Wilhoit et al. reference. Strausz et al. 2003. “The Chemistry of Alberta Oil Sands, Bitumens and Heavy Oils. Alberta Energy Research Institute verifies the presence of these and similar compounds in heavy crude oil. Several boiling points, shown in ° C., are above the maximum cracker temperature of 413° C. proposed in CA 2,764,676, supra.
TABLE 1Boilingpoint atatmosphericBoiling point atpressure50 psig(760 mm(2550 mmIncrease inCompoundmercury)mercury)boiling pointanthracene34141574phenanthrene339414751-heptadecanethiol34841870n-pentadecylcyclopentane35242169n-tetradecylcyclohexane355426719,10-dithiooctadecane34641771n-hexadecylcyclopentane36443470n-hexadeclcyclohexane379451721-eicosanethiol3834557211,12-dithiodocosane39046474
Increasing the boiling point of cracked and un-cracked heavy crude oil components, especially alkanes and thiols, to temperatures above the cracker operating temperature will cause them to over-crack resulting in unnecessary hydrogen free radical consumption which would otherwise be available for asphaltene free radical quenching to prevent undesirable coke formation.
Accordingly, there exists a need for an improved means of upgrading heavy hydrocarbons, including heavy crude oils, providing one or more of the following desirable features: scalability; portability; simplified processing; elimination or reduction of heavy metals, acids, chlorides, nitrogen, asphaltenes, micro-carbon residue (MCR) and coke; reduction of sulfur content; greater than 35% conversion of 525+° C. boiling point component of heavy crude oil feedstock without excessive coke formation; reduction of viscosity and TAN without the need for expensive purge or sweep gas; elimination of the need for purge gas or sweep gas; reduced operating pressure; elimination of the need for sequential cracking and distillation/condensation of condensable and non-condensable cracked and un-cracked heavy crude oil components; faster cracking with little or no coke (i.e. toluene insolubles) formation; and faster use of THFA, including THFA recycling, with better THFA product properties.